Method of acidizing a geological formation and method of determining an effectiveness of acidizing

ABSTRACT

A method of acidizing a geological formation is provided. A method of determining an effectiveness of the acidizing with NMR spectroscopy is also provided. Various embodiments of the method of acidizing and the method of determining the effectiveness of the acidizing are specified.

BACKGROUND OF THE INVENTION Technical Field

The present invention relates to a method acidizing a geologicalformation and a method of determining an effectiveness of the acidizingwith NMR spectroscopy.

Description of the Related Art

The “background” description provided herein is for the purpose ofgenerally presenting the context of the disclosure. Work of thepresently named inventors, to the extent it is described in thisbackground section, as well as aspects of the description which may nototherwise qualify as prior art at the time of filing, are neitherexpressly or impliedly admitted as prior art against the presentinvention.

Acidizing operations are common practices in oil and gas producing wellsand water injection wells to remove damages that form as a result ofdrilling operations and to enhance the productivity/injectivity of thereservoir. Acids are used to create macro-pore channels (wormholes) thatfluidly connect the undamaged regions in the reservoir to the wellbore.The created wormholes facilitate the flow of formation fluids (e.g. oiland/or gas) from the reservoir to the wellbore by increasing theeffective wellbore radius. In addition, the wormholes enhance theinjectivity of water in water injection wells.

The productivity enhancement after an acidizing operation is a functionof the acid penetration radius from the wellbore. A total recovery ofthe well productivity after an acidizing operation requires an acidpenetration radius of at least 3 meters from the wellbore in the case ofwells that have not been affected by damage in near-wellbore zones[Muskat, M.: Physical Principles of Oil Production, McGraw-Hill Book Co.Inc., New York City (1947) 242]. To achieve this high level of acidpenetration radius, the acid should be injected at the maximum possibleinjection rates. However, at high injection rates, the rate of acidconsumption increases. The relation of the acid injection rate to theacid consumption rate is described by Damkholer number (N_(Da)), whichis a ratio between the acid reaction rate to the acid injection rate asfollows [Fredd, C. N. and Fogler H. S.: “The Influence of ChelatingAgents on the Kinetics of Calcite Dissolution”, J. Colloid InterfaceSci., 204 (1), 1998, 187-197]:

$N_{Da} = \frac{\tau\; D_{e}^{2/3}L}{Q}$where r is the rock tortuosity factor, D_(e) is the effective diffusioncoefficient, L is the core length, and Q is the acid injection rate.Additionally, the Peclet number is used to describe the acid injectionrate to the acid consumption rate when the reaction is controlled by themass transfer rate. The Peclet number is a ratio of the acid convectionrate to the acid diffusion rate as follows [Gomaa, A. M., Mahmoud, M.A., and Nasr-El-Din, H. A., Laboratory Study of Diversion UsingPolymer-Based In-Situ-Gelled Acids, SPE Production & Operations Journal26(3), 2011, 278-290, doi:10.2118/132535-PA; incorporated herein byreference in its entirety]:

$N_{pe} = \frac{v\; L}{D_{l}}$where ν is the Darcy velocity, L is the rock sample length, and D_(t) isthe longitudinal dispersion coefficient.

A preferred injection rate in acidizing of carbonate formations isdefined as the injection rate at which the wormholes are generated withthe least amount of acid consumption. Wormholes are created to connectthe reservoir to the wellbore by bypassing damages in order to enhancewellbore productivity by increasing the effective wellbore radius in theformation. Wang et al. [Wang, Y., Hill, A. D., and Schechter, R. S., TheOptimum Injection Rate for Matrix Acidizing of Carbonate Formations.Paper presented at the SPE Annual Technical Conference and Exhibition,1993, Houston, Tex. doi:10.2118/26578-MS] found that the preferredinjection rate in acidizing of carbonate formations is a function ofacid concentration and temperature. They revealed that the amount of theacid consumed to generate wormholes at preferred injection rates waslower for low concentration acid solutions compared to highconcentration acid solutions. According to Wang et al., at the sameinjection rates, 1.2 grams of a high concentration acid solution (15 wt.% HCl acid) was used to generate wormholes in a carbonate formation,whereas the acid amount was around 0.59 grams for a low concentrationacid solution (3.4 wt. % HCl acid).

During the acid reaction with the carbonate formations, the pressuredrop in generated wormholes is considered to be zero. The pressure dropduring the acid flow and wormhole creation can be expressed as follows[Daccord, G., Touboul, E., and Lenormand, R., Carbonate Acidizing:Toward a Quantitative Model of the Wormholing Phenomenon. SPE ProductionEngineering Journal 4(1), 1989, 63-68, doi:10.2118/16887-PA]:

${p(t)} = {\frac{\mu\; Q}{k\;\pi\; r_{o}^{2}}\left\lbrack {L - {L_{e}(t)}} \right\rbrack}$where p(t) is the pressure drop at time t, μ is the dynamic viscosity, Qis the acid injection rate, k is the rock sample permeability, r_(o) isthe rock sample radius, L is the rock sample length, and L_(e)(t) is thewormhole length at time t. Approaching p(t) to zero is an indication ofbreakthrough of the wormholes. In addition, computed tomography (CT) hasbeen used extensively to characterize and describe wormhole propagationin carbonate formations using different stimulation fluids. Gomaa et al.[Gomaa, A. M., Mahmoud, M. A., and Nasr-El-Din, H. A., Laboratory Studyof Diversion Using Polymer-Based In-Situ-Gelled Acids, SPE Production &Operations Journal 26(3), 2011, 278-290, doi:10.2118/132535-PA;incorporated herein by reference in its entirety] used CT scan to studywormhole propagation using an in-situ polymer-based gelled acid and ahydrochloric acid solution. The pressure drop and computed tomographyscan (CT scan) are currently used to define the preferred injection rateof acid in acidizing operations. These techniques are also used todetermine wormhole shapes in acid-treated carbonate formations. However,these techniques cannot determine the interconnectivity of the createdwormholes to the pores structures in the formation.

In view of the forgoing, one objective of the present disclosure is toprovide a method acidizing a geological formation, and a method ofdetermining an effectiveness of the acidizing with NMR spectroscopy,wherein an interconnectivity number is calculated from NMR spectrabefore and after the acidizing to determine fluid connectivity ofwormholes to pores structures of the geological formation.

BRIEF SUMMARY OF THE INVENTION

According to a first aspect, the present disclosure relates to a methodof acidizing a geological formation surrounding a wellbore, involving i)recording a first nuclear magnetic resonance (NMR) spectrum of a portionof the geological formation over a micro-pore relaxation range, ameso-pore relaxation range, and a macro-pore relaxation range, ii)calculating a first interconnectivity number by dividing a firstmicro-meso interconnectivity number to a first meso-macrointerconnectivity number, wherein the first micro-meso interconnectivitynumber is a ratio of an intensity of the first NMR spectrum at amicro-meso diffusional coupling to a peak intensity of the first NMRspectrum in the micro-pore relaxation range or the meso-pore relaxationrange, and the first meso-macro interconnectivity number is a ratio ofan intensity of the first NMR spectrum at a meso-macro diffusionalcoupling to a peak intensity of the first NMR spectrum in the meso-porerelaxation range or the macro-pore relaxation range, iii) acidizing thegeological formation by delivering a first stimulation fluid to theportion of the geological formation, thereby forming an acidizedgeological formation, iv) recording a second NMR spectrum of theacidized geological formation over the micro-pore relaxation range, themeso-pore relaxation range, and the macro-pore relaxation range, v)calculating a second interconnectivity number by dividing a secondmicro-meso interconnectivity number to a second meso-macrointerconnectivity number, wherein the second micro-mesointerconnectivity number is a ratio of an intensity of the second NMRspectrum at a micro-meso diffusional coupling to a peak intensity of thesecond NMR spectrum in the micro-pore relaxation range or the meso-porerelaxation range, and the second meso-macro interconnectivity number isa ratio of an intensity of the second NMR spectrum at a meso-macrodiffusional coupling to a peak intensity of the second NMR spectrum inthe meso-pore relaxation range or the macro-pore relaxation range, andvi) re-acidizing the acidized geological formation by delivering asecond stimulation fluid to the wellbore at a predetermined flow rate.

In one embodiment, the first interconnectivity number determines a fluidconnectivity between pore structures of the geological formation, andthe second interconnectivity number determines a fluid connectivitybetween pore structures of the acidized geological formation.

In one embodiment, the second interconnectivity number is non-linearlycorrelated with a permeability ratio of the geological formation, andthe method further involves calculating the permeability ratio of thegeological formation, wherein the permeability ratio is a ratio of apermeability of the acidized geological formation to the permeability ofthe geological formation.

In one embodiment, the geological formation is a carbonate formationwith a permeability of 1 to 50 millidarcy.

In one embodiment, the geological formation has a porosity of 5-50%.

In one embodiment, acidizing the geological formation is carried out ata temperature of 80-120° C., and re-acidizing the acidized geologicalformation is carried out at a temperature of 80-120° C.

In one embodiment, the first stimulation fluid has a pH of 1-6 and thesecond stimulation fluid has a pH of 1-6.

In one embodiment, the second stimulation fluid is a chelation-basedfluid that comprises 10-30 wt % of at least one chelating agent selectedfrom the group consisting of ethylenediamine tetraacetic acid (EDTA),hydroxyethylenediamine triacetic acid (HEDTA), and glutamic diaceticacid (GLDA), relative to the total weight of the second stimulationfluid, wherein the second interconnectivity number is 0.7-1.0.

In one embodiment, the second stimulation fluid is an emulsified acidthat comprises at least one mineral acid selected from the groupconsisting of hydrochloric acid, hydrofluoric acid, hydrobromic acid,hydroiodic acid, nitric acid, sulfuric acid, phosphoric acid, perchloricacid, and boric acid, wherein the second interconnectivity number is0.4-0.6.

In one embodiment, the second stimulation fluid is an acid solution thatcomprises 10-20 wt % of at least one mineral acid in freshwater,relative to the total weight of the second stimulation fluid, whereinthe at least one mineral acid is selected from the group consisting ofhydrochloric acid, hydrofluoric acid, hydrobromic acid, hydroiodic acid,nitric acid, sulfuric acid, phosphoric acid, perchloric acid, and boricacid.

In one embodiment, the wellbore is a vertical wellbore, a horizontalwellbore, or a multi-lateral wellbore.

In one embodiment, at least one wormhole is formed in the geologicalformation after the acidizing.

In one embodiment, the first and the second NMR spectra are recordedwith an NMR-logging tool.

In one embodiment, the predetermined flow rate is determined from acalibration curve that correlates the second interconnectivity number toa flow rate of the first stimulation fluid.

In one embodiment, the second stimulation fluid is a chelation-basedfluid that comprises 10-30 wt % of at least one chelating agent selectedfrom the group consisting of EDTA, HEDTA, and GLDA, relative to thetotal weight of the second stimulation fluid, wherein the predeterminedflow rate is 1-4 cm³/min.

According to a second aspect, the present disclosure relates to a methodof determining an effectiveness of acidizing a geological formation, themethod involving i) recording a first nuclear magnetic resonance (NMR)spectrum of the geological formation over a micro-pore relaxation range,a meso-pore relaxation range, and a macro-pore relaxation range, ii)calculating a first interconnectivity number by dividing a firstmicro-meso interconnectivity number to a first meso-macrointerconnectivity number, wherein the first micro-meso interconnectivitynumber is a ratio of an intensity of the first NMR spectrum at amicro-meso diffusional coupling to a peak intensity of the first NMRspectrum in the micro-pore relaxation range or the meso-pore relaxationrange, and the first meso-macro interconnectivity number is a ratio ofan intensity of the first NMR spectrum at a meso-macro diffusionalcoupling to a peak intensity of the first NMR spectrum in the meso-porerelaxation range or the macro-pore relaxation range, iii) acidizing thegeological formation by delivering a stimulation fluid to the wellbore,thereby forming an acidized geological formation, iv) recording a secondNMR spectrum of the acidized geological formation over the micro-porerelaxation range, the meso-pore relaxation range, and the macro-porerelaxation range, v) calculating a second interconnectivity number bydividing a second micro-meso interconnectivity number to a secondmeso-macro interconnectivity number, wherein the second micro-mesointerconnectivity number is a ratio of an intensity of the second NMRspectrum at a micro-meso diffusional coupling to a peak intensity of thesecond NMR spectrum in the micro-pore relaxation range or the meso-porerelaxation range, and the second meso-macro interconnectivity number isa ratio of an intensity of the second NMR spectrum at a meso-macrodiffusional coupling to a peak intensity of the second NMR spectrum inthe meso-pore relaxation range or the macro-pore relaxation range, vi)comparing the first interconnectivity number with the secondinterconnectivity number to determine the effectiveness of acidizing thegeological formation.

In one embodiment, the stimulation fluid is a chelation-based fluid thatcomprises 10-30 wt % of at least one chelating agent selected from thegroup consisting of ethylenediamine tetraacetic acid (EDTA),hydroxyethylenediamine triacetic acid (HEDTA), and glutamic diaceticacid (GLDA), relative to the total weight of the stimulation fluid,wherein the permeability ratio is 0.5-1.0.

The foregoing paragraphs have been provided by way of generalintroduction, and are not intended to limit the scope of the followingclaims. The described embodiments, together with further advantages,will be best understood by reference to the following detaileddescription taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the disclosure and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 represents NMR spectra of a geological formation over amicro-pore relaxation range, a meso-pore relaxation range, and amacro-pore relaxation range before and after an acidizing operation,wherein the geological formation is acidized with an acid solution thatincludes 15 wt % of hydrochloric acid dissolved in freshwater.

FIG. 2 represents NMR spectra of a geological formation over themicro-pore relaxation range, the meso-pore relaxation range, and themacro-pore relaxation range before and after an acidizing operation,wherein the geological formation is acidized with an acid solution thatincludes 15 wt % of hydrochloric acid dissolved in seawater.

FIG. 3 represents NMR spectra of a geological formation over themicro-pore relaxation range, the meso-pore relaxation range, and themacro-pore relaxation range before and after an acidizing operation,wherein the geological formation is acidized with an emulsified acid ata flow (injection) rate of 2 cm³/min.

FIG. 4 represents NMR spectra of a geological formation over themicro-pore relaxation range, the meso-pore relaxation range, and themacro-pore relaxation range before and after an acidizing operation,wherein the geological formation is acidized with a polymer-based gelledacid at a flow (injection) rate of 2 cm³/min.

FIG. 5 represents NMR spectra of a geological formation over themicro-pore relaxation range, the meso-pore relaxation range, and themacro-pore relaxation range before and after an acidizing operation,wherein the geological formation is acidized with a VES-based gelledacid at a flow (injection) rate of 2 cm³/min.

FIG. 6 represents NMR spectra of a geological formation over themicro-pore relaxation range, the meso-pore relaxation range, and themacro-pore relaxation range before and after an acidizing operation,wherein the geological formation is acidized with a chelation-basedfluid at a flow (injection) rate of 2 cm³/min, wherein thechelation-based fluid includes 20 wt % EDTA dissolved in freshwater.

FIG. 7 represents an interconnectivity number and pore volume tobreakthrough in a geological formation with respect to a flow(injection) rate of a stimulation fluid, wherein the stimulation fluidis a VES-based gelled acid.

FIG. 8 represents an interconnectivity number and pore volume tobreakthrough in a geological formation with respect to a flow(injection) rate of a stimulation fluid, wherein the stimulation fluidis an emulsified acid.

FIG. 9 represents an interconnectivity number and pore volume tobreakthrough in a geological formation with respect to a flow(injection) rate of a stimulation fluid, wherein the stimulation fluidis a polymer-based gelled acid.

FIG. 10 represents an interconnectivity number and pore volume tobreakthrough in a geological formation with respect to a flow(injection) rate of a stimulation fluid, wherein the stimulation fluidis individually, a chelation-based fluid that includes 20 wt % EDTA infreshwater, a chelation-based fluid that includes 20 wt % HEDTA infreshwater, and a chelation-based fluid that includes 20 wt % GLDA infreshwater.

FIG. 11 represents an average interconnectivity number of a geologicalformation after acidizing the geological formation individually with achelation-based fluid that includes 20 wt % EDTA in freshwater andseawater; a chelation-based fluid that includes 20 wt % HEDTA infreshwater and seawater; and a chelation-based fluid that includes 20 wt% GLDA in freshwater and seawater.

FIG. 12 is an image of a core holder that is used for corefloodingexperiments.

FIG. 13 is a calibration curve that correlates the interconnectivitynumber of a geological formation to a permeability ratio.

FIG. 14 illustrates a geological formation surrounding a wellboreundergoing acidizing and re-acidizing treatments.

FIG. 15 is a flow diagram showing the steps involved in the method ofacidizing a geological formation surrounding a wellbore.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Embodiments of the present disclosure will now be described more fullyhereinafter with reference to the accompanying drawings, in which some,but not all embodiments of the disclosure are shown.

The present disclosure will be better understood with reference to thefollowing definitions. As used herein, the words “a” and “an” and thelike carry the meaning of “one or more.” Within the description of thisdisclosure, where a numerical limit or range is stated, the endpointsare included unless stated otherwise. Also, all values and subrangeswithin a numerical limit or range are specifically included as ifexplicitly written out.

According to a first aspect, the present disclosure relates to a methodof acidizing a geological formation surrounding a wellbore.

As shown in FIGS. 14 and 15, the method of acidizing a geologicalformation 202 surrounding a wellbore 201 may involve the steps of i)recording a first nuclear magnetic resonance (NMR) spectrum of a portionof the geological formation 202 over a micro-pore relaxation range, ameso-pore relaxation range, and a macro-pore relaxation range, ii)calculating a first interconnectivity number by dividing a firstmicro-meso interconnectivity number to a first meso-macrointerconnectivity number, wherein the first micro-meso interconnectivitynumber is a ratio of an intensity of the first NMR spectrum at amicro-meso diffusional coupling to a peak intensity of the first NMRspectrum in the micro-pore relaxation range or the meso-pore relaxationrange, and the first meso-macro interconnectivity number is a ratio ofan intensity of the first NMR spectrum at a meso-macro diffusionalcoupling to a peak intensity of the first NMR spectrum in the meso-porerelaxation range or the macro-pore relaxation range, iii) acidizing thegeological formation 202 by delivering a first stimulation fluid 203 tothe portion of the geological formation 202, thereby forming an acidizedgeological formation, iv) recording a second NMR spectrum of theacidized geological formation over the micro-pore relaxation range, themeso-pore relaxation range, and the macro-pore relaxation range, v)calculating a second interconnectivity number by dividing a secondmicro-meso interconnectivity number to a second meso-macrointerconnectivity number, wherein the second micro-mesointerconnectivity number is a ratio of an intensity of the second NMRspectrum at a micro-meso diffusional coupling to a peak intensity of thesecond NMR spectrum in the micro-pore relaxation range or the meso-porerelaxation range, and the second meso-macro interconnectivity number isa ratio of an intensity of the second NMR spectrum at a meso-macrodiffusional coupling to a peak intensity of the second NMR spectrum inthe meso-pore relaxation range or the macro-pore relaxation range, andvi) re-acidizing the acidized geological formation by delivering asecond stimulation fluid 204 to the wellbore 201 at a predetermined flowrate.

The geological formation may be a carbonate formation, a sandstoneformation, a shale formation, a clay formation, etc. In a preferredembodiment, the geological formation is a carbonate formation, e.g.limestone or dolostone, which contains carbonate minerals, such ascalcite, aragonite, dolomite, etc. In another preferred embodiment, thegeological formation is a carbonate formation, which contains at least98 wt %, preferably at least 99 wt % of calcite, and less than 1.0 wt %,preferably 0.1-0.5 wt % of quartz. Each weight percentile is determinedby a compositional analysis of a sample rock from the geologicalformation using XRD, and is defined relative to the total weight of thesample rock. As used herein, the “sandstone formation” is a formationthat mainly contains quartz, feldspar, rock fragments, mica and numerousadditional mineral grains held together with silica and/or cement; the“shale formation” is a formation that mainly contains clay minerals andquartz; and the “clay formation” is a formation that mainly containschlorite, illite, kaolinite, montmorillonite and smectite.

The geological formation may have a permeability of 10 μd (microdarcy)to 500 md (millidarcy), preferably 100 μd to 400 md, preferably 500 μdto 300 md, preferably 1-200 md, preferably 1-50 md, preferably 2-40 md,preferably 3-30 md, preferably 4-20 md, preferably 5-15 md, preferablyabout 10 md. In a preferred embodiment, the geological formation is acarbonate formation that mainly contains Indiana limestone with anaverage permeability of preferably 4-20 md, preferably 5-15 md,preferably about 10 md. In one embodiment, a well logging tool, as knownto those skilled in the art such as an NMR-logging tool, is employed todetermine the permeability of the geological formation along adepth/length of the wellbore.

In one embodiment, the geological formation has an average porosity of5-50%, preferably 6-40%, preferably 7-30%, preferably 8-25%, preferably10-20%, preferably 12-18%, preferably about 15%. As used here, the term“porosity” refers to a total pore volume per unit volume of thegeological formation. The total porosity refers to a total volume ofisolated pores and empty spaces occupied by clay-bound water orformation fluids. The porosity of the geological formation may bemeasured by various methods as known to those skilled in the art, e.g.density, neutron porosity, nuclear magnetic resonance (NMR)spectroscopy, etc. In one embodiment, the porosity of the geologicalformation is measured by NMR spectroscopy. In addition, the term “pore”as used here refers to a discrete void within the geological formation,which may contain air, water, hydrocarbons or other fluids.

In one embodiment, the pores of the geological formation are identifiedby NMR spectroscopy, wherein nuclei (i.e. H⁺) present in the poresabsorb electromagnetic radiation of a specific frequency in the presenceof a strong magnetic field, and further provide an image of nuclideconcentration and subsequently a relaxation time of the pores.Accordingly, the pores may preferably be characterized as micro-poreswith a micro-pore relaxation range (i.e. a relaxation time of less than0.01 to 10 milli-seconds (mSec), preferably 0.01 to 10 mSec); meso-poreswith a meso-pore relaxation range (i.e. a relaxation time of 10 to 100mSec); and macro-pores with a macro-pore relaxation range (i.e. arelaxation time of 100 to at least 10,000 mSec, preferably 100 to 10,000mSec). FIG. 1 represents an exemplary NMR spectra before and after anacidizing operation over a micro-pore relaxation range, a meso-porerelaxation range, and a macro-pore relaxation range. In view of that,the “micro-pores” as used in this disclosure refers to pores present inthe geological formation that has a relaxation time in the range of lessthan 0.01 to 10 mSec, preferably 0.01 to 10 mSec; the “meso-pores” asused in this disclosure refers to pores in the geological formation thathas a relaxation time in the range of 10 to 100 mSec; and the“macro-pores” as used in this disclosure refers to pores in thegeological formation that has a relaxation time in the range of 100 toat least 10,000 mSec, preferably 100 to 10,000 mSec.

In one embodiment, the wellbore is a vertical wellbore, a horizontalwellbore, or a multi-lateral wellbore. As used here, a “verticalwellbore” is a wellbore that has a vertical section, which issubstantially perpendicular to a surface of the ground. As used here, a“horizontal wellbore” is a wellbore that has a vertical section and ahorizontal lateral section with an inclination angle (an angle betweenthe vertical section and the horizontal lateral section) of at least70°, preferably at least 80°, or in the range of 85° to 90°. As usedhere, a “multilateral wellbore” refers to a wellbore that has amain/central borehole and a plurality of laterals that are extendedoutwardly therefrom.

A downhole temperature of the wellbore may depend on the type of thewellbore and a depth of the wellbore. For example, in one embodiment,the wellbore is a vertical wellbore with a depth of 1-10 km, preferably2-6 km, wherein a downhole temperature of the wellbore is no more than150° C., preferably from about 80 to 120° C., preferably 90 to 110° C.In some embodiments, the wellbore is a horizontal wellbore and thetemperature may not vary significantly along a horizontal lateralsection of the wellbore.

The term “acidizing” as used in this disclosure refers to a processwhereby a pressurized fluid, i.e. a stimulation fluid, ispumped/injected to the geological formation through the wellbore,wherein the stimulation fluid dissolves sediments and/or mud solids,removes formation residues and/or fragments that inhibit permeability,and/or forms wormholes, in order to restore or enhance a production rateof formation fluids.

Depending on the type of the geological formation, the stimulation fluidmay interact differently with the formation to restore or enhance theproduction rate of formation fluids. For example, in a preferredembodiment, the geological formation is a carbonate formation, whereinthe stimulation fluid dissolves a portion of the formation as well asfragments that inhibit permeability. In another embodiment, thegeological formation is a sandstone formation, wherein the stimulationfluid reacts with soluble substances in the formation to enlarge pores.

The stimulation fluid may be pumped/injected into the wellbore at apressure below a fracture pressure of the geological formation to removeformation damages, residues and/or fragments. Accordingly, in someembodiments, the stimulation fluid is injected at a pressure of no morethan 5,000 psi, preferably 100 to 3,000 psi, preferably 200 to 2,000psi, preferably 300 to 1,000 psi. Alternatively, the stimulation fluidmay be pumped or injected into the wellbore at a pressure above afracture pressure of the geological formation (also known as acidfracturing) to remove formation damages and to induce fractures in theformation. Accordingly, in some embodiments, the stimulation fluid isinjected at a pressure of 1,000 to 30,000 psi, preferably 3,000 to20,000 psi, preferably 5,000 to 10,000 psi.

The stimulation fluid may be pumped or injected into the wellbore withvarious methods as known to those skilled in the art. For example, inone embodiment, injecting the stimulation fluid may be carried out bydisposing a nozzle on one end of a tube or a pipe that transfers thestimulation fluid to a downhole of the wellbore. Said nozzle may havevarious shapes and geometries, as known to those skilled in the art. Forexample, in one embodiment, the nozzle is a perforated tube with acapped end and perforations are circumferentially oriented along theperforated tube to create a radial flow of the stimulation fluid. Incertain embodiments, the stimulation fluid is injected through tubing,as known to those skilled in the art, which is located inside thewellbore to selectively acidize certain spots in the wellbore.

The stimulation fluid may be injected at various flow rates, dependingon a total volume of the wellbore. For example, in some embodiments, thestimulation fluid is injected at a flow rate of 1-1,000 L/min,preferably 20-800 L/min, preferably 50-500 L/min, preferably 100-300L/min. In some preferred embodiments, the stimulation fluid is injectedat a predetermined flow rate, which is calculated from a secondinterconnectivity number, as described in this disclosure. In view ofthe abovementioned flow rates, a total volume of the stimulation fluidthat is injected may vary in the range from about 100 to 400,000 L,preferably 1,000 to 300,000 L, preferably 2,000 to 200,000 L.

In one embodiment, the stimulation fluid has a pH of 0.5-6.5, preferably1-6, preferably 2-5, preferably 3-4, more preferably about 4. The pH ofthe stimulation fluid may be advantageously suited for acidizingoperations, however, a person having ordinary skill in the art mayadjust the pH of the stimulation fluid, for example with the use of abuffer, to avoid damage/corrosion to equipment, such as metal equipment,etc.

In a preferred embodiment, the stimulation fluid is a chelation-basedfluid that includes 10-30 wt %, preferably 15-25 wt %, preferably about20 wt % of at least one chelating agent, which is dissolved in 70-95 wt%, preferably 75-85 wt %, preferably about 80 wt % of an aqueous liquid,wherein each weight percentile is relative to the total weight of thechelation-based fluid. In a preferred embodiment, the at least onechelating agent is selected from the group consisting of EDTA(ethylenediamine tetraacetic acid), HEDTA (hydroxyethylenediaminetriacetic acid), and GLDA (glutamic diacetic acid). Further chelatingagents may be present in the stimulation fluid in addition to, or inlieu of the abovementioned chelating agents such as, without limitation,NTA (nitriolotriacetic acid), DTPA (diethylenetriaminepentaacetic acid),MGDA (methylglycinediacetic acid), HEIDA (2-hydroxyethyliminodiaceticacid), CDTA (trans-cyclohexane-1,2-diaminetetraacetic acid), EGTA(ethylene glycol-bis(β-aminoethyl ether)-N,N,N′,N′-tetraacetic acid),EDDA (ethylenediaminediacetic acid), propylene diamine tetraacetic acid(PDTA), ethylene diamine-N,N″-di(hydroxyphenylacetic) acid (EDDHA),ethylene diamine-N,N″-di-(hydroxy-methylphenyl acetic acid (EDDHMA), andderivatives and/or salts thereof.

As used here, the “aqueous liquid” refers to any water containingsolution, including saltwater, hard water, or freshwater. Accordingly,the term “saltwater” may include saltwater with a chloride ion contentin the range of between about 6,000 ppm and saturation, and is intendedto encompass seawater and other types of saltwater including groundwaterthat contains additional impurities typically found therein. The term“hard water” may include water having mineral concentrations betweenabout 2,000 mg/L and about 300,000 mg/L. The term “freshwater” mayinclude water sources that contain less than 6,000 ppm, preferably lessthan 5,000 ppm, preferably less than 4,000 ppm, preferably less than3,000 ppm, preferably less than 2,000 ppm, preferably less than 1,000ppm, preferably less than 500 ppm, preferably less than 200 ppm,preferably less than 100 ppm, preferably less than 50 ppm, preferablyless than 10 ppm, preferably less than 5 ppm, preferably less than 1 ppmof salts minerals and/or any other dissolved solids. The aqueous liquidmay be supplied from a natural source, such as an aquifer, a lake,and/or an ocean, and may be filtered to remove large solids. In oneembodiment, the aqueous liquid is seawater with a total dissolved solidin the range of 30,000 to 60,000 mg/L, preferably 35,000 to 55,000 mg/L.Water that is supplied from bays, lakes, rivers, creeks, and/orunderground water resources may also be referred to as “seawater.” Insome preferred embodiments, the aqueous liquid is freshwater with atotal dissolved solid of less than 3,000 mg/L, preferably 10-2,000 mg/L,preferably 50-1,000 mg/L. The aqueous liquid may further refer to adistilled and/or desalinated (deionized) water, for example, a waterhaving a resistivity of less than 30 MΩ·cm, preferably less than 20MΩ·cm, at room temperature (i.e. 20-30° C.).

In one embodiment, the stimulation fluid is an emulsified acid thatincludes a mineral acid, which is dispersed (or emulsified) in an oilphase in the presence of an emulsifier. Preferably, the mineral acid ispresent in the emulsified acid at a volumetric concentration of 60-80vol %, preferably 65-75 vol %, preferably about 70 vol %, and the oilphase is present in the emulsified acid at a volumetric concentration of20-40 vol %, preferably 25-35 vol %, preferably about 30 vol %, whereineach volume percentile is relative to the total volume of the emulsifiedacid. In some embodiments, the mineral acid is at least one selectedfrom the group consisting of hydrochloric acid, hydrofluoric acid,hydrobromic acid, hydroiodic acid, nitric acid, sulfuric acid,phosphoric acid, perchloric acid, and boric acid. In a preferredembodiment, the mineral acid consists of hydrochloric acid. The oilphase may include at least one of crude oil, diesel, kerosene, gascondensate, gas oil, gasoline, reformate, naphthalene, xylene, andtoluene, etc. In a preferred embodiment, the oil phase consists ofdiesel. The emulsifier may be at least one compound selected from thegroup consisting of an ethoxylated glycol, an ethoxylated phenol, apropoxylated glycol, a propoxylated phenol, an ethoxylated andpropoxylated glycol, and an ethoxylated and propoxylated phenol. Incertain embodiments, the emulsifier may contain an ethoxylated(polyethylene oxide-like) sequence to increase a hydrophilic characterof the emulsifier, and/or a propoxylated (polypropylene oxide-like)sequence to increase a lipophilic character of the emulsifier. Theemulsifier may be present at a volumetric concentration of 0.1-4 vol %,preferably 0.5-3 vol %, preferably 1.0-2.0 vol %, relative to the totalvolume of the emulsified acid. The emulsified acid may further include acorrosion inhibitor, which may be present at a concentration of 0.1-0.5%by volume, preferably 0.2-0.4% by volume, more preferably about 0.3% byvolume relative to the total volume of the emulsified acid. Examples ofthe corrosion inhibitor include, without limitation, barium borate,benzotriazole, cinnamaldehyde, 1,2-diaminopropane, dibutylamine,diethylhydroxylamine, dimethylethanolamine, 3,5-dinitrobenzoic acid,ethylenediamine, hexamethylenetetramine, hydrazine, lead oxide, lithiumnitrite, sodium nitrite, zinc borate, zinc dithiophosphate, zinc oxide,zinc phosphate, methanol, isopropanol, propargyl alcohol, an aliphaticamide, etc.

In one embodiment, the stimulation fluid is an acid solution thatincludes at least one mineral acid dissolved in water (e.g. seawater orpreferably freshwater). The at least one mineral acid may be selectedfrom the group consisting of hydrochloric acid, hydrofluoric acid,hydrobromic acid, hydroiodic acid, nitric acid, sulfuric acid,phosphoric acid, perchloric acid, and boric acid. In a preferredembodiment, the acid solution includes hydrochloric acid dissolved inthe aqueous liquid (e.g. seawater or preferably freshwater). The type ofthe mineral acid that is used in the acid solution may vary depending onthe type of the geological formation. Also, the abovementioned mineralacids may be mixed at various volumetric/weight concentrations. Forexample, in some preferred embodiment, the geological formation is acarbonate formation and the acid solution contains 10-20 wt %,preferably about 15 wt % of hydrochloric acid in seawater or preferablyfreshwater, relative to the total weight of the acid solution. In oneembodiment, the geological formation is a carbonate formation and theacid solution contains hydrochloric acid and hydrofluoric acid, whereina volume ratio of hydrochloric acid to hydrofluoric acid may be in therange of 2:1 to 12:1, preferably 4:1 to 9:1, preferably 5:1 to 7:1. Insome preferred embodiments, the acid solution further includes less than1.0 vol %, preferably 0.1-0.5 vol %, preferably 0.2-0.4 vol %,preferably about 0.3 vol % of a corrosion inhibitor (e.g. one or more ofthe aforementioned corrosion inhibitors), relative to the total volumeof the acid solution.

In certain embodiments, the stimulation fluid is a polymer-based gelledacid, which includes 1-10 wt %, preferably 2-8 wt %, preferably about 5wt % of at least one mineral acid (e.g. one or more of theaforementioned mineral acids, preferably hydrochloric acid); 0.1-2.0 wt%, preferably 0.2-1.0 wt %, preferably about 0.5 wt % of a copolymer(e.g. block copolymers of ethylene oxide and propylene oxide, blockcopolymers of polyethylene glycol and polypropylene glycol, etc.); lessthan 1.0 vol %, preferably 0.1-0.5 vol %, preferably 0.2-0.4 vol %,preferably about 0.3 vol % of a corrosion inhibitor (e.g. one or more ofthe aforementioned corrosion inhibitors); less than 1.0 vol %,preferably 0.2-0.7 vol %, preferably 0.3-0.6 vol %, preferably about0.45 vol % of a crosslinker (e.g. iron trichloride, a zirconium salt, analuminum salt, ferric chloride, etc.); and less than 1.0 vol %,preferably 0.1-0.4 vol %, preferably 0.2-0.3 vol %, preferably about0.25 vol % of a breaker (e.g. sodium erythorbate, calcium fluoride, anethoxylated alcohol, a sodium salt, isoascorbic acid, hydroxyaceticacid, etc.); and a balance of an aqueous liquid (seawater or preferablyfreshwater), wherein each weight percentile is relative to the totalweight of the polymer-based gelled acid. As used herein, the term“breaker” refers to an additive of the drilling fluid that provides adesired viscosity reduction in a specified period of time, for example,by breaking long-chain molecules into shorter segments. Also, the term“crosslinker” refers to an additive of the drilling fluid that can reactwith multiple-strand polymers to couple the molecules together, therebycreating a highly viscous fluid, with a controllable viscosity.

In one embodiment, the stimulation fluid is a VES-based gelled acid. Theterm “VES-based gelled acid” as used here refers to a gelled acid thatcontains a viscoelastic surfactant (VES). Accordingly, in someembodiments, the VES-based gelled acid includes 10-20 wt %, preferablyabout 15 wt % of at least one mineral acid (e.g. one or more of theaforementioned mineral acids, preferably hydrochloric acid); less than1.0 vol %, preferably 0.1-0.5 vol %, preferably 0.2-0.4 vol %,preferably about 0.3 vol % of a corrosion inhibitor (e.g. one or more ofthe aforementioned corrosion inhibitors); 1-10 wt %, preferably 2-8 wt%, preferably 3-5 wt % of a viscoelastic surfactant, and a balance of anaqueous liquid (preferably freshwater or seawater), wherein each weightpercentile is relative to the total weight of the VES-based gelled acid.As used here, a viscoelastic surfactant is a surfactant with moleculesthat are aggregated into worm-like micelles, differentiating them fromnon-viscoelastic surfactant molecules that are characterized by havingone long hydrocarbon chain per surfactant head-group and do not formingmicelles. Examples of the viscoelastic surfactant that may be used hereinclude, without limitation N-erucyl-N,N-bis(2-hydroxyethyl)-N-methylammonium chloride and potassium oleate. As used here, a surfactantrefers to a molecule (or molecules) comprises a hydrophilic head unitattached to one or more hydrophobic tails.

The stimulation fluid, as used in the present disclosure, is not limitedto the abovementioned stimulation fluids, and various other stimulationfluids, as known to those skilled in the art may be used in addition to,or in lieu of, the stimulation fluid.

In some embodiments, each of the aforementioned stimulation fluids (e.g.the chelation-based fluid, the emulsified acid, the acid solution, thepolymer-based gelled acid, and the VES-based gelled acid) may furtherinclude one or more additives selected from an alcohol, a glycol, anorganic solvent, a soap, a fragrance, a dye, a dispersant, a watersoftener, a bleaching agent, an antifouling agent, an antifoaming agent,an anti-sludge agent, a catalyst, a diverting agent, an oxygenscavenger, a sulfide scavenger, a retarder, a gelling agent, apermeability modifier, a bridging agent, a shale stabilizing agent (suchas ammonium chloride, tetramethyl ammonium chloride, or cationicpolymers), a clay treating additive, a polyelectrolyte, a freezing pointdepressant, an iron-reducing agent, etc. The aforementioned additives,when present, may have a mass concentration independently of 0.01-5 wt%, preferably 0.5-3 wt %, more preferably 0.8-2 wt %, relative to atotal weight of the stimulation fluid.

In one embodiment, acidizing the geological formation is carried out ata temperature of 80-120° C., preferably 85-115° C., preferably 90-110°C., preferably about 100° C. In some alternative embodiments, acidizingthe geological formation is carried out at a temperature below 80° C.,preferably 50-80° C., preferably 60-75° C. In view of that, in someembodiments, acidizing the geological formation is carried out in a timeperiod of no longer than 5 hours, preferably in the range of 1 to 4hours, preferably 2 to 3 hours, preferably in a continuous fashion.

Once the stimulation fluid is delivered to the wellbore and furtherinjected into the geological formation surrounding the wellbore, anacidized geological formation may preferably be formed having at leastone wormhole. As used herein, the term “wormhole” refers to a macro-porechannel that may penetrate up to several meters into carbonateformations, as a result of acid dissolution of limestone or dolomite inthe carbonate formations. In certain embodiments, the at least onewormhole has a length in the range of 0.1-150 m, preferably 1-20 m,preferably 2-10 m, preferably 3-8 m, from the wellbore. In terms of thepresent disclosure, the wormholes that form after acidizing thegeological formation may preferably be considered “macro-pores” with amacro-pore relaxation range as characterized by NMR spectroscopy.

Well operations, i.e. operations that are performed to produce formationfluids from the geological formation, e.g. drilling, production,maintenance, servicing, etc., may reduce an initial permeability of thegeological formation by 10-100%, or 20-95%, or 30-90%, or 40-85%, or50-80%. The “initial permeability” as used here refers to a permeabilityof the geological formation before any of the abovementioned welloperations. In view of that, acidizing the geological formation with thestimulation fluid may recover at least a portion of the initialpermeability that is inhibited/plugged by the abovementioned welloperations. In some embodiments, acidizing the geological formation withthe stimulation fluid may recover at least 80%, preferably at least 90%,preferably at least 95%, preferably at least 99%, preferably 100% of theinitial permeability. In some preferred embodiments, acidizing thegeological formation with the stimulation fluid recovers 100% of theinitial permeability. For example, in a preferred embodiment, thegeological formation has an initial permeability of 5 to 15 md,preferably about 10 md before the abovementioned well operations. Afterthe abovementioned well operations, the permeability of the geologicalformation may be reduced to 0.1-2 md, or 0.2-1.5 md, or 0.5-1.0 md. Inview of this embodiment, the permeability of the geological formationafter acidizing with the stimulation fluid (e.g. the chelation-basedfluid) is substantially the same as the initial permeability, i.e. 5 to15 md, preferably about 10 md.

The method of acidizing the geological formation involves one or morepre-acidizing steps and one or more post-acidizing steps. In somepreferred embodiments, the pre-acidizing steps and the post-acidizingsteps are carried out for re-acidizing the geological formation with apreferred stimulation fluid at a predetermined flow (injection) rateand/or determining an effectiveness of the acidizing.

As a pre-acidizing step, the method involves recording a first NMRspectrum from the geological formation. The term “first NMR spectrum” asused in this disclosure refers to an NMR spectrum, which is recordedbefore acidizing the geological formation. The first NMR spectrum of thegeological formation may preferably be recorded over the micro-porerelaxation range, the meso-pore relaxation range, and the macro-porerelaxation range, as shown in FIGS. 1-6. In one embodiment, the firstNMR spectrum is obtained and recorded with an NMR-logging tool.

In terms of the present disclosure, nuclear magnetic resonance (NMR)spectroscopy refers to a well-logging method that provides informationabout nuclear magnetic properties of the geological formation, forexample, fluid saturation by imaging nuclide concentration (i.e. H⁺).During NMR spectroscopy a nucleus absorbs electromagnetic radiation of aspecific frequency in the presence of a strong magnetic field.Parameters of the NMR-logging tool may be altered depending on the typeof the geological formation, and a person of ordinary skill in the artmay adjust those parameters before and/or during NMR spectroscopy.

As a further pre-acidizing step, the method involves calculating a firstinterconnectivity number using the first NMR spectrum. In terms of thepresent disclosure, the term “first interconnectivity number” refers toan interconnectivity number, which is obtained from the first NMRspectrum, and represents a fluid connectivity of pore structures in thegeological formation before the acidizing.

As used in this disclosure, the term “interconnectivity number” refersto a quantitative parameter preferably on a scale of 0-1.0 (or 0-100%)that represents interconnectivity (i.e. fluid connectivity) between porestructures of the geological formation. In certain embodiments, theinterconnectivity number may be above unity (or 100%), but preferably nomore than 5 (or 500%), preferably no more than 4 (or 400%). Theinterconnectivity number may represent how well micro-pores, meso-pores,and macro-pores of a formation are fluidly connected. In an NMR spectrumthat is taken after the acidizing, e.g. the first NMR spectrum, theinterconnectivity number may represent how well pore structures of thegeological formation (preferably micro-pores and meso-pores) are fluidlyconnected to one another. In an NMR spectrum that is taken after theacidizing, the interconnectivity number may represent how well porestructures of the geological formation (preferably micro-pores andmeso-pores) are fluidly connected to the wormholes. For example, in oneembodiment, an interconnectivity number of less than 0.2, or less than0.1, or less than 0.05 represents that pore structures of the geologicalformation are poorly connected. In one embodiment, the pore structuresare not fluidly connected (i.e. blocked) when the interconnectivitynumber is substantially zero. In one embodiment, an interconnectivitynumber of 0.2-0.6, or 0.25-0.55, or 0.3-0.5 represents that porestructures of the geological formation are fairly/moderately connected.Also, in one embodiment, an interconnectivity number of greater than0.5, preferably greater than 0.55, preferably greater than 0.6represents that pore structures of the geological formation are fluidlyconnected preferably without substantially having blocks/damages thatinhibit permeability.

In terms of the present disclosure, the interconnectivity number is aratio of a micro-meso interconnectivity number to a meso-macrointerconnectivity number, as shown in the following equation:ICN=ICN_(micro/meso)/ICN_(meso/macro)wherein ICN is the interconnectivity number, ICN_(micro/meso) is themicro-meso interconnectivity number, and ICN_(meso/macro) is themeso-macro interconnectivity number.

As used herein, the term “micro-meso interconnectivity number” refers toa quantitative parameter preferably on the scale of 0-1.0 (or 0-100%)that represents interconnectivity (i.e. fluid connectivity) betweenmicro-pores and meso-pores in a geological formation. In certainembodiments, the micro-meso interconnectivity number may be above unity(or 100%), but preferably no more than 5 (or 500%), preferably no morethan 4 (or 400%). The micro-meso interconnectivity number is preferablya ratio of an intensity of an NMR spectrum of a geological formation ata micro-meso diffusional coupling to a peak intensity (i.e. the largerintensity) of the NMR spectrum in the micro-pore relaxation range or themeso-pore relaxation range. For example, in one embodiment, an NMRspectrum is recorded from a geological formation after an acidizingoperation, as shown in FIG. 1. In view of that, the intensity of the NMRspectrum at the micro-meso diffusional coupling is about 0.075, whereasthe peak intensity (i.e. the larger intensity) of the NMR spectrum inthe micro-pore relaxation range or the meso-pore relaxation range isabout 0.12. Therefore, the micro-meso interconnectivity number is about0.075/0.12=0.625 or 62.5%.

As used herein, the term “meso-macro interconnectivity number” refers toa quantitative parameter preferably on the scale of 0-1.0 (or 0-100%)that represents interconnectivity (i.e. fluid connectivity) betweenmeso-pores and macro-pores in a geological formation. In certainembodiments, the meso-macro interconnectivity number may be above unity(or 100%), but preferably no more than 5 (or 500%), preferably no morethan 4 (or 400%). The meso-macro interconnectivity number is preferablya ratio of an intensity of the NMR spectrum at a meso-macro diffusionalcoupling to a peak intensity (i.e. a larger intensity) of the NMRspectrum in the meso-pore relaxation range or the macro-pore relaxationrange. For example, in one embodiment, an NMR spectrum is recorded froma geological formation after an acidizing operation, as shown in FIG. 1.In view of that, the intensity of the NMR spectrum at the meso-macrodiffusional coupling is about 0.07, whereas the peak intensity (i.e. thelarger intensity) of the NMR spectrum in the meso-pore relaxation rangeor the macro-pore relaxation range is about 0.225. Therefore, themeso-macro interconnectivity number is about 0.07/0.225=0.31 or 31%.

As used in this disclosure, the term “diffusional coupling” or“diffusion coupling” refers to a time period during an NMR spectroscopywhere nuclei (i.e. H⁺) present in the pores lose their coherent energyas they move within the pores having different relaxation times. Thediffusion coupling of various NMR spectra are shown in FIGS. 1-6.

As a post-acidizing step, the method involves recording a second NMRspectrum from the geological formation. The term “second NMR spectrum”as used in this disclosure refers to an NMR spectrum, which is recordedafter acidizing the geological formation. The second NMR spectrum of thegeological formation may preferably be recorded over substantially thesame ranges as the first NMR spectrum is recorded, i.e. the micro-porerelaxation range, the meso-pore relaxation range, and the macro-porerelaxation range, as shown in FIGS. 1-6. In a preferred embodiment, thesecond NMR spectrum is obtained and recorded with the NMR-logging tool.

As a further post-acidizing step, the method involves calculating asecond interconnectivity number using the second NMR spectrum. In termsof the present disclosure, the term “second interconnectivity number”refers to an interconnectivity number, which is obtained from the secondNMR spectrum, and represents a fluid connectivity of pore structures inthe acidized geological formation.

Similar to the first interconnectivity number, the secondinterconnectivity number is a ratio of the micro-meso interconnectivitynumber to the meso-macro interconnectivity number, wherein themicro-meso interconnectivity number and the meso-macro interconnectivitynumber are obtained from the second NMR spectrum. The micro-mesointerconnectivity number and the meso-macro interconnectivity number arecalculated in substantially the same way as described in the firstinterconnectivity number.

In one embodiment, the stimulation fluid is the emulsified acid, asdescribed, wherein the second interconnectivity number is in the rangeof 0.4-0.6, or 0.45-0.55, or about 0.5. Accordingly, pore structures ofthe geological formation after acidizing with the emulsified acid arepreferably moderately connected. In another embodiment, the stimulationfluid is the acid solution, which contains 15 wt % of hydrochloric aciddissolved in seawater, wherein the second interconnectivity number isless than 0.1, or less than 0.05, or in the range of 0-0.01.Accordingly, pore structures of the geological formation after acidizingwith the acid solution are not fluidly connected, or poorly connected.Yet in another embodiment, the stimulation fluid is the polymer-basedgelled acid, as described, wherein the second interconnectivity numberis less than 0.1, or less than 0.05, or in the range of 0-0.01.Accordingly, pore structures of the geological formation after acidizingwith the polymer-based gelled acid are not fluidly connected, or incertain embodiments poorly connected. In still a further embodiment, thestimulation fluid is the VES-based gelled acid, as described, whereinthe second interconnectivity number is in the range of 0.3-0.55, or0.35-0.5, or about 0.45. Accordingly, pore structures of the geologicalformation after acidizing with the polymer-based gelled acid aremoderately connected. In some preferred embodiments, the stimulationfluid is the chelation-based fluid, as described, wherein the secondinterconnectivity number is in the range of 0.7-1.0, preferably0.8-0.98, preferably 0.85-0.95. Accordingly, pore structures of thegeological formation after acidizing with the chelation-based fluid arefluidly connected without having blocks/damages that inhibitpermeability.

Once the first and the second interconnectivity numbers are calculated,in a preferred embodiment, the acidized geological formation isre-acidized by a preferred stimulation fluid and at a predetermined flowrate. In terms of the present disclosure, “re-acidizing” the geologicalformation is carried out in substantially the same way as in“acidizing.” For example, in some embodiments, re-acidizing the acidizedgeological formation is carried out at a temperature of 80-120° C.,preferably 85-115° C., preferably 90-110° C., preferably about 100° C.,and in a time period of no longer than 5 hours, preferably in the rangeof 1 to 4 hours, preferably 2 to 3 hours, preferably in a continuousfashion.

The “preferred stimulation fluid” that is used in re-acidizing theacidized geological formation may be preferably the stimulation fluidthat provides a highest second interconnectivity number, when acidizingis carried out. In view of that, in some preferred embodiments, thepreferred stimulation fluid is the chelation-based fluid. FIG. 6represents the first and the second NMR spectra of the chelation-basedfluid, which includes 20 wt % of EDTA diluted in freshwater. Inaddition, FIG. 11 represents the second interconnectivity number ofvarious chelation-based fluids when used as the stimulation fluid foracidizing the geological formation.

In some preferred embodiments, the “predetermined flow rate” of thepreferred stimulation fluid, which is used for the re-acidizing, isdetermined from a calibration curve that correlates the secondinterconnectivity number to a flow rate of the stimulation fluid. FIGS.7-10 represent calibration curves for various stimulation fluids atvarious flow rates (or injection rates). In view of that, thepredetermined flow rate is a flow rate of the stimulation fluid thatprovides a highest second interconnectivity number after the acidizing.The predetermined flow rate of various stimulation fluids for acidizingthe geological formation are shown in FIGS. 7-10.

For pilot-scale acidizing, in some embodiments, the stimulation is theVES-based gelled acid, as described, wherein the predetermined flow rateis in the range of 2-6 cm³/min, preferably 2.5-3.5 cm³/min, preferablyabout 3 cm³/min, as shown in FIG. 7. In some other embodiments, thestimulation is the emulsified acid, as described, wherein thepredetermined flow rate is in the range of 3-6 cm³/min, preferably 3-5cm³/min, preferably about 3 cm³/min, as shown in FIG. 8. Yet in somealternative embodiments, the stimulation is the polymer-based gelledacid, as described, wherein the predetermined flow rate is in the rangeof 3.5-6 cm³/min, preferably 4-5 cm³/min, preferably about 4 cm³/min, asshown in FIG. 9. In some preferred embodiments, the stimulation is thechelation-based fluid, as described, wherein the predetermined flow rateis in the range of 1-4 cm³/min, preferably 1.5-3 cm³/min, preferablyabout 2 cm³/min, as shown in FIG. 10.

For large-scale acidizing, in some embodiments, the stimulation is theVES-based gelled acid, as described, wherein the predetermined flow rateis in the range of 1-1,000 L/min, preferably 20-800 L/min, preferably50-500 L/min, preferably 100-300 L/min. In some other embodiments, thestimulation is the emulsified acid, as described, wherein thepredetermined flow rate is in the range of 5-1,000 L/min, preferably50-800 L/min, preferably 100-600 L/min, preferably 200-400 L/min. Yet insome alternative embodiments, the stimulation is the polymer-basedgelled acid, as described, wherein the predetermined flow rate is in therange of 5-1,000 L/min, preferably 50-800 L/min, preferably 100-600L/min, preferably 200-400 L/min. In some preferred embodiments, thestimulation is the chelation-based fluid, as described, wherein thepredetermined flow rate is in the range of 1-600 L/min, preferably 5-400L/min, preferably 10-200 L/min, preferably 50-100 L/min.

In a preferred embodiment, the second interconnectivity number isnon-linearly correlated with a permeability ratio of the geologicalformation, as shown in FIG. 13. In view of that, the method furtherinvolves calculating the permeability ratio of the geological formation.The permeability ratio may be correlated with the permeability ratio viathe following equation:Y=Ax ² +Bx+Cwherein Y is the permeability ratio, x is the second interconnectivitynumber, A is a negative dimensionless number in the range of −2 to −1,preferably −1.5 to −1.1, preferably about −1.28; B is a positivedimensionless number in the range of 2-2.5, preferably about 2.18; and Cis a negative dimensionless number in the range of −0.1 to −0.01,preferably −0.08 to −0.02, preferably about −0.05.

As used herein, the “permeability ratio” is a ratio of a permeability ofthe acidized geological formation to the permeability of the geologicalformation. In one embodiment, the stimulation fluid is the emulsifiedacid, as described, wherein the permeability ratio is in the range of0.3-0.7, or 0.4-0.6. In another embodiment, the stimulation fluid is theacid solution, which contains 15 wt % of hydrochloric acid dissolved inseawater as described, wherein the permeability ratio is less than 0.2,or 0.05-0.15. In another embodiment, the stimulation fluid is thepolymer-based gelled acid, as described, wherein the permeability ratiois less than 0.2, or 0.05-0.15. In still a further embodiment, thestimulation fluid is the VES-based gelled acid, as described, whereinthe permeability ratio is in the range of 0.3-0.6, or 0.35-0.5. In somepreferred embodiments, the stimulation fluid is the chelation-basedfluid, as described, wherein the permeability ratio is in the range of0.5-1.0, preferably 0.6-0.98, preferably 0.7-0.95.

According to a second aspect, the present disclosure relates to a methodof determining an effectiveness of acidizing the geological formation.According to the method, once the first and the second interconnectivitynumbers are calculated, the method further involves a step of comparingthe first interconnectivity number with the second interconnectivitynumber to determine the effectiveness of acidizing the geologicalformation.

In one embodiment, comparing the first interconnectivity number with thesecond interconnectivity number is carried out by calculating aneffectiveness number, which is a ratio of the second interconnectivitynumber to the first interconnectivity number. In terms of the presentdisclosure, the “effectiveness number” is a dimensionless number thatdetermines an effectiveness of acidizing a geological formation. In viewof that, when the effectiveness number is below unity, i.e. in the rangeof 0-1, the acidizing may preferably be characterized as “inefficient.”When the effectiveness number is substantially equal to unity, theacidizing may be characterized as “fairly efficient.” When, theeffectiveness number is greater than unity, e.g. in the range of 1-10,or preferably 1-5, the acidizing may be characterized as “efficient.”When, the effectiveness number is greater than 5, preferably greaterthan 10, e.g. in the range of 10-100, the acidizing may preferably becharacterized as “very efficient.”

The examples below are intended to further illustrate protocols for themethod of acidizing the geological formation and the method ofdetermining an effectiveness of the acidizing, and are not intended tolimit the scope of the claims.

EXAMPLE 1—Materials and Experimental Work

In the following examples, coreflooding experiments were performed using3-inch Indiana limestone cores at 100° C. at different injection ratesof various stimulation fluids such as an emulsified acid, a hydrochloric(HCl) acid solution, a polymer-based gelled HCl acid, a viscoelasticsurfactant (VES)-based gelled HCl acid, and chelating agents. NuclearMagnetic Resonance (NMR) spectroscopy was used to evaluate theefficiency of different stimulation fluids in creating wormholes and theinterconnectivity of the wormholes with the surrounding pores in therock. The interconnectivity number is introduced to describe theinterconnectivity between the created wormhole and the rest of the poresin the rock.

Eleven different stimulation fluids were tested at different injectionrates. These fluids were prepared from their initial concentrationsusing either freshwater or seawater. In all coreflooding experiments thecore initial permeability was measured using 3 wt. % KCl (potassiumchloride), and also it was used as a pre- and post-flushing fluid.

Low permeability Indiana limestone core samples were used in allcoreflooding experiments with an average permeability of 10 md and anaverage porosity of 15%. The mineralogical composition by XRD (X-RayDiffractions) shows that the cores mainly consisted of 99.5 wt. %calcite and 0.5 wt. % quartz. All cores have 1.5-inch (3.81-cm) diameterand 3-inch (7.62-cm) length.

EXAMPLE 2—Interconnectivity Number

The interconnectivity number was used to describe and quantitativelycharacterize the interconnectivity between the generated wormholes andthe pore structures in the rock. The higher the interconnectivitynumber, the better the quality of the generated wormhole. Stimulationfluids that yield high interconnectivity numbers were considered goodstimulation fluids and considered as less damaging fluids. Theinterconnectivity number was estimated at the interconnection betweenthe pore structures. The first one was calculated for the connectionbetween micro and meso pores and the second one was calculated for theconnection between meso and macro pores. The following equation was usedto determine the interconnectivity number (ICN):

ICN=Intensity of the diffusion coupling/maximum intensity of the twopore structures

The ICN ratio can be used when triple pore structures (micro/meso/macropores) are present after acidizing the core samples. The ICN ratio canbe determined as follows:ICN_(Ratio)=ICN_(micro/meso)/ICN_(meso/macro)where ICN_(micro/meso) is the interconnectivity number between micro andmeso pores and ICN_(meso/macro) is the interconnectivity number betweenmeso and macro pores.

For example, using the NMR data in FIG. 1 (in the after acidizingcurve), the interconnectivity number between micro and meso pores isequal to 0.075/0.12=0.625 or 62.5%. The intensity of the diffusioncoupling between the micro and macro pores is 0.075 and the maximumintensity of the two pore structures (in this case micro pores have thehighest intensity) is 0.12. The interconnectivity number between mesoand macro pores is equal to 0.07/0.225=0.31 or 31%. To assess thequality of the stimulation fluid in wormhole generation the ratiobetween the two numbers was used. The ICN between micro-meso pores willbe divided by that between meso-macro pores. The higher the number, thegood the interconnectivity between the pore structures and the lessdamaging the stimulation fluid is. For the core plug in FIG. 1 that wasstimulated by 15 wt. % HCl prepared in freshwater at 2 cm³/min, theratio is 2. The ICN for the core in FIG. 2 (the one treated by 15 wt. %HCl prepared in seawater at 2 cm³/min) was zero between the micro andmeso pores and it was 0.4 between meso and macro pores(ICN=0.18/0.45=0.4). The ratio between the two numbers is zero. Thisratio is a good measure for the formation damage associated with thestimulation fluid. Only NMR can capture this phenomenon, which cannot becharacterized by CT scan and pressure drop. According to that, NMR isfound to be an advantageous tool besides mercury injection capillarypressure (MICP) that can provide information about interconnection ofpore structures in a formation.

EXAMPLE 3—Stimulation of Indiana Limestone Cores Using Retarded/GelledHCl

The composition of the stimulation fluids that are used in this studyare listed in Table 1. Systems 3, 4, and 5 are VES-based gelled HCl,polymer-based gelled HCl, and emulsified acid, respectively. In thispart the focus will be on the NMR evaluation of the generated wormholesbecause as mentioned earlier other methods such as pressure drop and CTscans cannot capture the full details of the wormholes. The three acidsystems were evaluated extensively in the literature and their diversionability was confirmed in carbonate acidizing.

TABLE 1 Stimulation fluids used in this study. Conc. No. Fluid wt. %Base Composition  1 HCl 15 Freshwater 15 wt. % HCl + 0.4 vol. %corrosion inhibitor (CI)  2 HCl 15 Seawater 15 wt. % HCl + 0.4 vol. % CI 3 VES-based 15 Freshwater 15 wt. % HCl, 4 wt. % VES, gelled HCl 0.3vol. % CI  4 Polymer-based  5 Freshwater 5 wt. % HCl, 0.5 wt. % co-gelled HCl polymer, 0.4 vol. % CI + 0.45 vol. % crosslinker (FeCl₃) +0.25 vol. % beaker (sodium erythorbate)  5 Emulsified 15 Freshwater 15wt. % HCl (70 vol. %) + acid diesel (30 vol. %) + 0.3 vol. % CI  6 EDTA20 Freshwater 20 wt. % EDTA in freshwater, pH = 4  7 EDTA 20 Seawater 20wt. % EDTA in seawater, pH = 4  8 HEDTA 20 Freshwater 20 wt. % HEDTA infreshwater, pH = 4  9 HEDTA 20 Seawater 20 wt. % HEDTA in seawater, pH =4 10 GLDA 20 Freshwater 20 wt. % GLDA in freshwater, pH = 4 11 GLDA 20Seawater 20 wt. % GLDA in seawater, pH = 4

FIG. 3 shows the NMR profile for the core treated by emulsified acid at2 cm³/min. Emulsified acid did not cause damages, while connected thepores. The wormhole generation enlarged the existing macro pores andalso the acid leak off in the core enlarged the existing micro pores andenhanced the interconnectivity between the two pore structures: Theinterconnectivity number (ICN) was 0.02/0.45=4.5% before acidstimulation and increased to 0.1/0.5=20% after treating the core byemulsified acid.

FIG. 4 shows the NMR profiles before and after stimulating the coreusing the polymer-based gelled HCl. This stimulation fluid has strongdiversion ability and it created larger wormholes and the acid leak offalso enlarged other pores in the rock. Polymer-based gelled HCl has highmolecular weight and it gets adsorbed and retained in theinterconnection of the different pore structures. The polymer residuecompletely plugged the interconnection between the micro and meso poresand this resulted in ICN of zero. The ICN between the meso and macropores is 0.03/0.55=5.5% and the ratio between the two ICN's is zero.This acid system created wormholes and diverted the fluid efficientlybut the created wormholes are not well-connected to the other porestructures in the rock. The created wormhole is completely isolated fromthe micro pores and has small interconnectivity with the meso pores andthis will result is inefficient acid treatment using this type of acids.

FIG. 5 shows the NMR profiles before and after treating the core usingVES-based gelled HCl. The VES acid system has good diversion ability andit is less damaging than polymer-based gelled HCl. VES surfactants havesmaller molecular weight and their retention will be smaller compared topolymers. VES generally adsorb on the carbonate rocks and plugs smallerpores and pore throats in the carbonate rocks. The wormholes that aregenerated after acidizing the rocks with VES-based gelled HCl has arelaxation time of 3000 msec compared to the initial relaxation time of1750 msec. The interconnectivity number (ICN) between the micro and mesopores is 0.01/0.13=0.077 (7.7%). The ICN between the meso and macropores (wormhole) is 0.055/0.3=0.183 (18.3%). The ratio between the twoICN is 0.42 (42%). In view of these results, the VES-based gelled HCl isa better stimulation fluid than polymer-based gelled HCl in thediversion process because it causes less damage to the poreinterconnectivity. According to the coreflooding experiments, thepreferred injection rate of VES-based gelled HCl was found to be about 2cm³/min.

In this study, a different approach was used to determine a preferredinjection rate. The preferred injection rate is an injection rate thatyields the highest wormhole interconnectivity with the pore structuresof the rock (i.e. the highest ICN ratio). Four different corefloodingexperiments were carried out using Indiana limestone rocks at 100° C. at1, 2, 4, and 6 cm³/min injection rates. The ICN was determined betweenthe micro and meso pores and also between the meso and macro (wormholes)pores. The ratio of the ICN_(micro-meso) to ICN_(meso-wormhole) wasplotted versus the injection rate. The injection rate that provided thehighest ICN was taken as the preferred injection rate.

FIG. 7 shows the new approach followed in this study to determine thepreferred injection rate for the WS-based gelled HCl. The NMR showedthat, the generated wormhole is not well-connected to the rest of thepores in the rock as indicated by the value of ICN, 18.3%. FIG. 7 showsthat the preferred injection rate is 3 cm³/min because it resulted in42% ICN ratio. This rate resulted in the creation of wormholes that arewell-connected with the rest of the pores in the rock leading to higherstimulation efficiency with this acid system. The preferred injectionrate of 3 cm³/min resulted in a successful stimulation treatmentcompared to the injection rate of 2 cm³/min that resulted in an ICNratio of 29 compared to 42 in the case of 3 cm³/min. By defining thepreferred injection rate as being the highest ICN ratio, the damage thatmay result from the precipitation during stimulation operations maydisappear. As indicated earlier dominant channels and wormholes mayinitially be present in the rocks, but they may not be connected withthe pore networks that contain formation fluids. For example,precipitations on the wormhole surface may plug the connection betweenthe created wormhole and other pores in the rock.

The conventional definition of the preferred injection rate is based onlocating the rate at which the least amount of acid is needed to createa dominant wormhole. This definition does not consider the quality ofthe wormhole and its connectivity with the surrounding pores. Thedefinition of interconnectivity number of the present disclosure isbased on fluid connectivity between the created wormholes and thesurrounding pore structures in the rock. The conventional definitionconsidered only the creation of the wormhole regardless it is connectedor with the rock or not. In view of that, wormholes may be generated,but the walls of these wormholes may be completely plugged by thereaction products, thus the wormholes do not allow formation fluids toflow into the wormholes. Assessing the wormhole generation based on theinterconnectivity number can help one of ordinary skill in the art toselect the best acid and to determine the preferred injection rate.

Similar results were obtained for the emulsified acid system as shown inFIG. 8. In this case higher ICN ratio was obtained compared to theVES-based gelled HCl because the emulsified acid is less damagingcompared to VES-based gelled HCl. VES is adsorbed inside the rock andplugs the interconnections between the pores. Emulsified acid is gentleto the rock, thus it yielded an ICN ratio of 52% compared to 42% in thecase of VES-based gelled HCl.

FIG. 9 shows a preferred injection rate of 3 cm³/min from thecoreflooding experiments and 4 cm³/min from the ICN ratio plot for thein-situ polymer-based gelled HCl. This system was reported to be verydamaging during carbonate acidizing [Gomaa, A. M., Mahmoud, M. A., andNasr-El-Din, H. A., Laboratory Study of Diversion Using Polymer-BasedIn-Situ-Gelled Acids. SPE Production & Operations Journal 26(3), 2011,278-290, doi:10.2118/132535-PA; incorporated herein by reference in itsentirety]. The values of ICN ratio were very small compared to VES-basedgelled HCl and emulsified acid systems. The maximum ICN ratio obtainedwith this system at the preferred injection rate was 17.5% compared to52% for the emulsified acid. As reported in the literature this isattributed to the polymer residue around the wormholes that reduces theinterconnectivity between the wormhole and the pores in the rock.

FIG. 10 shows the results of EDTA, HEDTA, and GLDA chelating agents. Thebehavior of the three chelates is very similar in both pore volumes tobreakthrough and ICN ratio plots. The pore volume to breakthrough showsa preferred injection rate between 1 and 2 cm³/min. The ICN ratio showsan preferred injection rate of 2 cm³/min. Chelating agents yieldedhigher ICN ratio compared to the previous HCl-based acid system becausethey are compatible with both fluids and rock and do not causeprecipitation. The three chelates yielded ICN ratio greater than 80%.

EXAMPLE 4—Stimulation of Indiana Limestone Cores Using Chelating Agents

Three different chelating agents were used namely; EDTA, HEDTA, and GLDAto form a chelation-based stimulation fluid. The concentration was fixedat 20 wt. % and the pH was 4 and all experiments were performed at 100°C. Each chelating agents was diluted in both freshwater and seawater.

FIG. 6 shows the NMR profiles for the Indiana limestone core treated by20 wt. % EDTA chelating agent diluted in freshwater. Initially the corehad two pore structures, micro and macro pores, and the two porestructures were disconnected. After the treatment, EDTA created a thirdpore structures and enhanced the connectivity between the three porestructures. The ICN between the micro and meso pores is 0.09/0.27 or0.33, and the ICN between the meso pores and wormholes (macro pores) is0.37. The ratio between the two ICN is 89% which is very high. Thismeans EDTA created very well connected wormhole without causing anydamage to the rock. Similar experiment was conducted using 20 wt. % EDTAdiluted in seawater at the same conditions.

FIG. 11 shows the summary of different coreflooding experimentsperformed for 20 wt % chelating agents diluted in both freshwater andseawater. Chelating agents prepared in seawater did not adversely affectthe interconnectivity between the pores and the created wormholes. Allthe tested chelation-based stimulation fluids revealed high ICN ratios,indicating that chelating agents when diluted in freshwater or seawatercan be effectively used to stimulate carbonate reservoirs compared toHCl acid solutions that may form precipitations around the wormholes,particularly when prepared in seawater.

EXAMPLE 5—Relationship Between Core Permeability after Stimulation andInterconnectivity Number

The core permeability at the wormhole wall was measured using the coreholder shown in FIG. 12. The 3 wt % KCl was injected into the createdwormhole and the production was allowed from the indicated port only.The permeability was measured for different cores treated with differentacid systems and the ICN number ratio was determined using the NMR forthe created wormholes. The connection between the pore structures in therock and the wormhole was also investigated.

FIG. 13 shows a strong relation between the ICN ratio and thepermeability ratio of the core, which is a ratio of the permeabilityafter acid-treatment to an initial permeability of the core. Thepermeability ratio approaches to unity when the stimulation fluid doesnot damage the pore connectivity of the core. Also the permeabilityratio approaches to zero when the pore connectivity of the core iscompletely plugged, and no fluid pathway is found between the generatedwormhole and the pore structures of the core. As shown in FIG. 13, lowICN ratio is associated with low permeability ratio (measuredpermeability/initial core permeability). High ICN ratio means goodconnectivity between the pores and the wormhole and in turn, good flowpath and high permeability.

Detailed NMR scanning of the core was found to be a good assessing toolfor the type of the stimulation fluid and locating the createdwormholes. For example, using a 3-inch length Indiana limestone core,conventional coreflooding experiments showed that 2 cm³/min injectionrate generates the minimum acid volume VES-based gelled HCl, however,NMR scan showed an injection rate of 3 cm³/min generates the highestpore interconnectivity for the wormhole. Gelled acidizing fluids such asHCl based on polymers created wormholes that were clearly identified byCT scan and pressure drop but the NMR scan showed that these wormholesare completely isolated from the rest of the surrounding pore structuresdue to polymer residue plugging the pores. This isolation will reducethe production rate due to minimal radial fluid entry at the wormholesurface. Radial flooding experiments through the wormhole and productionfrom the side of the core confirmed the findings of NMR scan regardingthe interconnection between the wormholes and other pores in the rock.Strong relationship was found between the interconnectivity number andcore radial permeability around the wormhole.

Thus, the foregoing discussion discloses and describes merely exemplaryembodiments of the present invention. As will be understood by thoseskilled in the art, the present invention may be embodied in otherspecific forms without departing from the spirit or essentialcharacteristics thereof. Accordingly, the disclosure of the presentinvention is intended to be illustrative, but not limiting of the scopeof the invention, as well as other claims. The disclosure, including anyreadily discernible variants of the teachings herein, defines, in part,the scope of the foregoing claim terminology such that no inventivesubject matter is dedicated to the public.

The invention claimed is:
 1. A method of acidizing a geologicalformation surrounding a wellbore, comprising: recording a first nuclearmagnetic resonance (NMR) spectrum of a portion of the geologicalformation over a micro-pore relaxation range, a meso-pore relaxationrange, and a macro-pore relaxation range; calculating a firstinterconnectivity number by dividing a first micro-mesointerconnectivity number to a first meso-macro interconnectivity number,wherein the first micro-meso interconnectivity number is a ratio of anintensity of the first NMR spectrum at a micro-meso diffusional couplingto a peak intensity of the first NMR spectrum in the micro-porerelaxation range or the meso-pore relaxation range, and the firstmeso-macro interconnectivity number is a ratio of an intensity of thefirst NMR spectrum at a meso-macro diffusional coupling to a peakintensity of the first NMR spectrum in the meso-pore relaxation range orthe macro-pore relaxation range; acidizing the geological formation bydelivering a first stimulation fluid to the portion of the geologicalformation, thereby forming an acidized geological formation; recording asecond NMR spectrum of the acidized geological formation over themicro-pore relaxation range, the meso-pore relaxation range, and themacro-pore relaxation range; calculating a second interconnectivitynumber by dividing a second micro-meso interconnectivity number to asecond meso-macro interconnectivity number, wherein the secondmicro-meso interconnectivity number is a ratio of an intensity of thesecond NMR spectrum at a micro-meso diffusional coupling to a peakintensity of the second NMR spectrum in the micro-pore relaxation rangeor the meso-pore relaxation range, and the second meso-macrointerconnectivity number is a ratio of an intensity of the second NMRspectrum at a meso-macro diffusional coupling to a peak intensity of thesecond NMR spectrum in the meso-pore relaxation range or the macro-porerelaxation range; and re-acidizing the acidized geological formation bydelivering a second stimulation fluid to the wellbore at a predeterminedflow rate.
 2. The method of claim 1, wherein the first interconnectivitynumber determines a fluid connectivity between pore structures of thegeological formation, and wherein the second interconnectivity numberdetermines a fluid connectivity between pore structures of the acidizedgeological formation.
 3. The method of claim 1, wherein the secondinterconnectivity number is non-linearly correlated with a permeabilityratio of the geological formation, and the method further comprising:calculating the permeability ratio of the geological formation, whereinthe permeability ratio is a ratio of a permeability of the acidizedgeological formation to the permeability of the geological formation. 4.The method of claim 1, wherein the geological formation is a carbonateformation with a permeability of 1 to 50 millidarcy.
 5. The method ofclaim 1, wherein the geological formation has a porosity of 5-50%. 6.The method of claim 1, wherein acidizing the geological formation iscarried out at a temperature of 80-120° C., and wherein re-acidizing theacidized geological formation is carried out at a temperature of 80-120°C.
 7. The method of claim 1, wherein the first stimulation fluid has apH of 1-6, and wherein the second stimulation fluid has a pH of 1-6. 8.The method of claim 1, wherein the second stimulation fluid is achelation-based fluid that comprises 10-30 wt % of at least onechelating agent selected from the group consisting of ethylenediaminetetraacetic acid (EDTA), hydroxyethylenediamine triacetic acid (HEDTA),and glutamic diacetic acid (GLDA), relative to the total weight of thesecond stimulation fluid.
 9. The method of claim 8, wherein the secondinterconnectivity number is 0.7-1.0.
 10. The method of claim 1, whereinthe second stimulation fluid is an emulsified acid that comprises atleast one mineral acid selected from the group consisting ofhydrochloric acid, hydrofluoric acid, hydrobromic acid, hydroiodic acid,nitric acid, sulfuric acid, phosphoric acid, perchloric acid, and boricacid, and wherein the second interconnectivity number is 0.4-0.6. 11.The method of claim 1, wherein the second stimulation fluid is an acidsolution that comprises 10-20 wt % of at least one mineral acid infreshwater, relative to the total weight of the second stimulationfluid, and wherein the at least one mineral acid is selected from thegroup consisting of hydrochloric acid, hydrofluoric acid, hydrobromicacid, hydroiodic acid, nitric acid, sulfuric acid, phosphoric acid,perchloric acid, and boric acid.
 12. The method of claim 1, wherein thewellbore is a vertical wellbore, a horizontal wellbore, or amulti-lateral wellbore.
 13. The method of claim 1, wherein at least onewormhole is formed in the geological formation after the acidizing. 14.The method of claim 1, wherein the first and the second NMR spectra arerecorded with an NMR-logging tool.
 15. The method of claim 1, whereinthe predetermined flow rate is determined from a calibration curve thatcorrelates the second interconnectivity number to a flow rate of thefirst stimulation fluid.
 16. The method of claim 1, wherein the secondstimulation fluid is a chelation-based fluid that comprises 10-30 wt %of at least one chelating agent selected from the group consisting ofEDTA, HEDTA, and GLDA, relative to the total weight of the secondstimulation fluid, and wherein the predetermined flow rate is 1-4cm³/min.
 17. A method of determining an effectiveness of acidizing ageological formation, the method comprising: recording a first nuclearmagnetic resonance (NMR) spectrum of the geological formation over amicro-pore relaxation range, a meso-pore relaxation range, and amacro-pore relaxation range; calculating a first interconnectivitynumber by dividing a first micro-meso interconnectivity number to afirst meso-macro interconnectivity number, wherein the first micro-mesointerconnectivity number is a ratio of an intensity of the first NMRspectrum at a micro-meso diffusional coupling to a peak intensity of thefirst NMR spectrum in the micro-pore relaxation range or the meso-porerelaxation range, and the first meso-macro interconnectivity number is aratio of an intensity of the first NMR spectrum at a meso-macrodiffusional coupling to a peak intensity of the first NMR spectrum inthe meso-pore relaxation range or the macro-pore relaxation range;acidizing the geological formation by delivering a stimulation fluid tothe wellbore, thereby forming an acidized geological formation;recording a second NMR spectrum of the acidized geological formationover the micro-pore relaxation range, the meso-pore relaxation range,and the macro-pore relaxation range; calculating a secondinterconnectivity number by dividing a second micro-mesointerconnectivity number to a second meso-macro interconnectivitynumber, wherein the second micro-meso interconnectivity number is aratio of an intensity of the second NMR spectrum at a micro-mesodiffusional coupling to a peak intensity of the second NMR spectrum inthe micro-pore relaxation range or the meso-pore relaxation range, andthe second meso-macro interconnectivity number is a ratio of anintensity of the second NMR spectrum at a meso-macro diffusionalcoupling to a peak intensity of the second NMR spectrum in the meso-porerelaxation range or the macro-pore relaxation range; and comparing thefirst interconnectivity number with the second interconnectivity numberto determine the effectiveness of acidizing the geological formation.18. The method of claim 17, wherein the second interconnectivity numberis non-linearly correlated with a permeability ratio of the geologicalformation, and the method further comprising: calculating thepermeability ratio of the geological formation, wherein the permeabilityratio is a ratio of a permeability of the acidized geological formationto the permeability of the geological formation.
 19. The method of claim18, wherein the stimulation fluid is a chelation-based fluid thatcomprises 10-30 wt % of at least one chelating agent selected from thegroup consisting of ethylenediamine tetraacetic acid (EDTA),hydroxyethylenediamine triacetic acid (HEDTA), and glutamic diaceticacid (GLDA), relative to the total weight of the stimulation fluid. 20.The method of claim 19, wherein the permeability ratio is 0.5-1.0.